Argillaceous formations account for about 75% of drilled sections in oil, gas and geothermal subterranean wells and cause approximately 90% of wellbore instability-related problems during the drilling operations. The formations, including shales, mudstones, siltstones and claystones, are of a fine-grained nature and low permeability but yet are fairly porous and normally saturated with formation water. The combination of these characteristics results in the formations being highly susceptible to time-dependent effective mud support change, which is a function of the difference between the mud (wellbore) pressure and pore fluid (formation) pressure. See Mody, F. K. and Hale, A. H., A Borehole Stability Model to Couple the Mechanics and Chemistry of Drilling Fluid Interaction, Proc. SPE/IADC Drilling Conf., Amsterdam, The Netherlands, pp. 473–490 (1993); van Oort, E., Hale, A. H. and Mody, F. K., Manipulation of Coupled Osmotic Flows for Stabilisation of Shales Exposed to Water-Based Drilling Fluids, Proc. 70th SPE Annual Technical Conference and Exhibition, Dallas, USA, pp. 497–509 (1995) and Tan, C. P., Rahman, S. S., Richards, B. G. and Mody, F. K., Integrated Approach to Drilling Fluid Optimisation for Efficient Shale Instability Management, Proc. SPE International Oil and Gas Conference and Exhibition in China, Beijing, China, pp. 441–456 (1998), incorporated herein by reference.
When drilling under an overbalance condition in an argillaceous formation without an effective flow barrier present at the wellbore wall, mud pressure will penetrate progressively into the formation. See van Oort, E., Hale, A. H. and Mody, F. K., Manipulation of Coupled Osmotic Flows for Stabilisation of Shales Exposed to Water-Based Drilling Fluids, Proc. 70th SPE Annual Technical Conference and Exhibition, Dallas, USA, pp. 497–509 (1995) and Tan, C. P., Richards, B. G. and Rahman, S. S., Managing Physico-Chemical Wellbore Instability in Shales with the Chemical Potential Mechanism, Proc. Asia Pacific Oil and Gas Conference and Exhibition, Adelaide, Australia, pp. 107–116 (1996), incorporated herein by reference. Without a physical isolation (impermeable) membrane on the wall, an effective barrier will not be formed as a result of the low permeability of the formation. Due to the saturation and low permeability of the formation, penetration of a small volume of mud filtrate into the formation results in a considerable increase in pore fluid pressure near the wellbore wall. The increase in pore fluid pressure reduces the effective mud support which leads to a less stable wellbore condition, possibly resulting in instability.
The fine pore size and negative charge of clay on pore surfaces cause argillaceous materials to exhibit membrane behaviour. See Whitworth, T. M. and Fritz, S. J., Electrolyte-induced Solute Permeability Effects in Compacted Smectite Membranes, Applied Geochemistry, pp. 533–546 (1994), incorporated herein by reference. Hence, the flow of water out of (or into) such materials due to the chemical potential gradient is somewhat similar to the osmotic flow of water through a semi-permeable membrane. The chemical potential gradient across the membrane is generally related to the difference in salt concentration i.e. water activity between the drilling fluid and formation. See Mody, F. K. and Hale, A. H., A Borehole Stability Model to Couple the Mechanics and Chemistry of Drilling Fluid Interaction, Proc. SPE/IADC Drilling Conf., Amsterdam, The Netherlands, pp. 473–490 (1993); van Oort, E., Hale, A. H. and Mody, F. K., Manipulation of Coupled Osmotic Flows for Stabilisation of Shales Exposed to Water-Based Drilling Fluids, Proc. 70th SPE Annual Technical Conference and Exhibition, Dallas, USA, pp. 497–509 (1995) and Tan, C. P., Richards, B. G. and Rahman, S. S., Managing Physico-Chemical Wellbore Instability in Shales with the Chemical Potential Mechanism, Proc. Asia Pacific Oil and Gas Conference and Exhibition, Adelaide, Australia, pp. 107–116 (1996), incorporated herein by reference. With the water activity of the drilling fluid being lower than the formation activity, an osmotic outflow of pore fluid from the formation, as part of the chemical potential mechanism, will reduce or lessen the increase in pore pressure due to mud pressure penetration. If the osmotic outflow is greater than the inflow due to mud pressure penetration, there will be a net flow of water out of the formation into the wellbore. This will result in the lowering of the pore fluid pressure below the in-situ value. The associated increase in the effective mud support will lead to an improvement in the stability of the wellbore.
For an ideal semi-permeable membrane, only water can pass through the membrane. However, argillaceous materials exhibit a non-ideal semi-permeable (‘leaky’) membrane behaviour to water-based solutions because argillaceous materials have a range of pore sizes including wide pore throats which result in significant permeability to salts. The wide throats reduce the solute interaction with the pore surfaces which increase the permeability of the membrane to the solutes. Infiltration of solutes will reduce the chemical potential (water activity) of the formation. This will gradually reduce the chemical potential difference between the drilling fluid and the formation, and consequently reduce the osmotic pressure, which can be sustained across the membrane. Hence, the sustainable osmotic pressure will be dependent on the pore size distribution of the argillaceous materials.
The total aqueous potential (pore pressure and chemical potential) of the pore fluid increases with the increase in pore pressure and/or chemical potential (decrease in salt concentration). See Chenevert, M. E. and Osisanya, S. O., Shale Swelling at Elevated Temperature and Pressure, Proc. 33rd U.S. Rock Mechanics Symposium, Santa Fe, USA, pp. 869–878 (1992) and Tan, C. P., Richards, B. G., Rahman, S. S. and Andika, R., Effects of Swelling and Hydrational Stress in Shales on Wellbore Stability, Asia Pacific Oil and Gas Conference and Exhibition, Kuala Lumpur, Malaysia, pp. 345–349 (1997), incorporated herein by reference. As described above, pore pressure can increase due to mud pressure penetration and osmotic inflow (into the formation) when the water activity of the drilling fluid is higher (lower salt concentration) than the formation activity. In addition, the solute which flowed from the formation of higher salt concentration to the drilling fluid across a ‘leaky’ membrane will increase the chemical potential (water activity) of the formation. When the total aqueous potential of the pore fluid increases, water will be absorbed into the clay platelets. This water absorption will result in either the platelets moving further apart i.e. swelling if they are free to expand, or the generation of hydrational stress if swelling is constrained. The hydrational stress will cause a change in the stress distribution around the wellbore and an increase in shear stress which may result in wellbore instability.
From the drilling fluid-argillaceous formation interaction processes described above, it is advantageous to induce a high osmotic outflow from the formation and to reduce the flow of salt across the membrane. This will lead to an increase in effective mud support and either prevent or decrease formation swelling and/or generation of hydrational stress. The osmotic outflow and salt flow are strongly dependent on the membrane efficiency generated by either the drilling fluid (e.g. oil-based mud) or the drilling fluid-formation system (e.g. water-based drilling fluid) and water activity of the formation and drilling fluid (salt type and concentration). Osmotic outflow is additionally dependent on macroscopic flow properties of the formation such as permeability and porosity.
One of the key parameters which can be manipulated to increase the osmotic outflow and to reduce salt flow is membrane efficiency. The efficiency is a measure of the capacity of the membrane to sustain osmotic pressure between the drilling fluid and argillaceous formation. The osmotic outflow increases and salt flow decreases with increase in membrane efficiency. Oil-based muds generate a highly efficient membrane through their water-in-oil emulsion i.e. independently of the formation. As a result, the stability of wells drilled in argillaceous formations with such mud systems is greatly enhanced. However, oil-based muds generally do not always meet environmental compliance in many parts of the world which results in high costs in disposing of the drilling wastes associated with the muds.
Hence, there is a need for environmentally acceptable water-based drilling fluids which can generate a highly efficient membrane on the borehole wall in argillaceous formations in order to meet future requirements of the petroleum industry.